The need for managing the price risk of electricity is greater than in many other markets because there is a high variation in the price of electricity over both time and space. There is a high variation in the price of electricity over time because it is difficult to store electric power, necessitating that the electricity be produced when demanded. Even under normal conditions, electricity prices may fluctuate widely over the course of a day. The high variation in the price of electricity over space is due to the physical nature of the power network. Power flow over a particular transmission line between two locations in an electric power network cannot be directly controlled unless highly specialized and generally expensive equipment is installed because electric power flows over all possible paths in accordance with their impedance. As a result, when electric power is transferred into or out of a power transmission grid, that transfer of power may affect the distribution of electricity on any transmission line in the network.
Congestion in the transmission system can have a significant effect on the price of electricity. When one transmission line in the network is loaded at or near its full capacity, power can be rerouted over a different transmission line to avoid the congested line only with economic consequences. Even if the transmission of power is congested between only two locations, that congestion potentially affects the prices of electricity at other locations in the network. The price of electricity downstream of the congested line tends to increase, encouraging additional power generation to be brought on line to serve the load downstream of the congested line. Meanwhile, the price of electricity upstream of the congested line will tend to decrease, discouraging power generation upstream of the congested line.
An Independent System Operator (ISO) or a Regional Transmission Operator (RTO) coordinates, controls and monitors the operation of the electrical power system. An RTO must meet the requirements set forth in Federal Energy Regulatory Commission (FERC) Order 2000. An ISO or RTO may cover parts of one or more states within the United States or neighboring countries.
As part of a functioning competitive electricity market, FERC Orders 888 and 889 define how Independent Power Producers (IPPs) and power marketers are allowed fair access to transmission systems, and mandates the implementation of the Open Access Same-Time Information System (OASIS) to facilitate the fair handling of transactions between electric power transmission suppliers and their customers.
Computer systems within both the ISOs and the RTOs generate a daily operating plan that determines for each time increment for the following day how much energy will be supplied by each generator, and maintain a record of the actual prices for each time increment for each transmission element under its purview.
As noted, the laws of nature, rather than the law of contracts, govern the power flows from electricity suppliers to consumers. By nature, electricity flows over the path of least resistance and will travel down whatever paths are made available to it. Because the suppliers and consumers of electricity are interconnected on the transmission grid, the voltage and current at any point are determined by the behavior of the system as a whole (i.e., impedance) rather than by the actions of any two individual market players adjusting generation or load on the system. Consequently, the delivery of 100 megawatts of electricity differs dramatically as compared to a simple fuel oil delivery in which 100 barrels of oil are physically piped or trucked between the oil supplier's depot and the consumer's facility.
Two different market designs are sometimes used for transmission services. The first approach assumes that it is more trouble than it is worth to charge each system user for the cost the user imposes on the system. In this case, external costs are apportioned to users according to local rules and FERC-approved transmission tariffs. If congestion cannot be fully managed using re-dispatch, the transmission operators use a priority system to decide who remains on line. Transmission costs are “socialized” (shared out to everyone) in this approach.
The second approach associates transmission charges with the costs each local power provider imposes on the system. The transmission system controller calculates a “constraint price” or “shadow price” of transmission on every congested line and then charges users according to their marginal contributions to congestion. Loosely, the shadow price is the change in the objective value of the optimal solution of an optimization problem obtained by relaxing the constraint by one unit. When a line becomes overloaded, system controllers redispatch the system, which increases the implicit price of using the line, until market participants voluntarily reduce the line loadings. A priority system for allocating transmission is not employed.
The advantages of this second approach are that all transmission users can see the economic impacts of their choices on all other users, and line capability is allocated to those who value it most. The chief disadvantage of the second approach is that the transmission price calculation is complex, expost, and can lead to significant price variations, depending on the level of system congestion.
Various approaches have been proposed to manage the above-described price risk of electricity. For example, a power generator can hedge against the risk that the price of electricity will fall at a particular electricity location via a forward contract. A power forward contract is a privately negotiated agreement between commercial parties containing a binding obligation to deliver electricity at a specified location and price. A significant disadvantage of forward contracts is that the market for forward contracts can be illiquid at particular locations. Forward markets achieve higher liquidity by concentrating the market activity into a few standard locations. There are thousands of different locations in the power network but only a few locations in which any forward liquidity exists. Therefore, it may be difficult for the generator to find a willing buyer of the forward contract at an acceptable price at its specific location.